Drilling, completion, workover, production, injection and similar operations in subterranean sandstone and siliceous formations may cause siliceous materials to migrate toward the wellbore and block the pores in the formation, thereby reducing permeability. Such subterranean formations are often referred to as "damaged". Permeability reduction, or damage, may result from different kinds of drilling and production operations. For example, "mud damage" is caused by mechanisms such as the blocking of the pores of the formation with drilling mud solids and formation fines. Acid solutions are often used to improve the permeability of such damaged sandstones and other siliceous formations surrounding oil and gas wells and thereby increase the production of fluids from these formations. The methods employed, generally referred to as sandstone acidizing processes, normally involve the injection of an aqueous solution containing a mixture of hydrochloric and hydrofluoric acids into the formation and the subsequent return production of spent acid from the formation back into the wellbore. These acidizing solutions of hydrofluoric and hydrochloric acids are routinely injected into wells in sandstone formations to dissolve and remove materials restricting flow of reservoir fluids to or from the wellbore. The reaction products of an acidizing process may be iron, silicon, or aluminum compounds or other solid dissolved species. However, formation damage can also occur by precipitation of such reaction products from spent acidizing solutions of hydrofluoric and hydrochloric acids. Acidizing solutions can also corrode tubing, casing, and downhole equipment. Consequently, there is a need for acidizing processes and solutions which have a reduced tendency to precipitate reaction products and corrode equipment.
In view of the risks involved in acidizing processes, such processes should only be used on formations in which production can be substantially improved by an acidizing treatment. The production increase which can be obtained from damage removal by acidizing can be estimated if the ratio of the damaged permeability (k.sub.d) to the undamaged permeability (k.sub.o) is known. (See Acidizing Fundamentals, B. B. Williams, J. L. Gidley and R. S. Schecter, Millet the Printer, Inc., Dallas, Tex., 1979, pg. 6) In general, unless the ratio of k.sub.d /k.sub.o is less than about 0.5, acidizing processes will not be used to remove damage, increase permeability and thereby increase production. With a ratio of k.sub.d /k.sub.o above about 0.5, any potential production increase would be insufficient to pay for the acidizing treatment. Also, in formations having a ratio of k.sub.d /k.sub.o above and about 0.5, the acidizing treatment may actually damage the formation and reduce production.
It is desirable that acids injected into sandstone formations to improve formation permeability first react with the siliceous materials which block reservoir fluid flow and then maintain all reaction products dissolved in the spent acid solution. Reaction products, particularly compounds of silicon and aluminum which dissolve in the acid solution, are preferably removed from the formation with the spent acid. However, as discussed in the paper "Understanding Sandstone Acidizing Leads to Improved Field Practices" by C. M. Shaughnessy and K. R. Kunze, Journal of Petroleum Technology, July, 1981, Pages 1196 to 1202, silicon compounds precipitate from conventional acidizing solutions (5 to 28 wt.% hydrochloric acid plus 1 to 6 wt.% hydrofluoric acid) when the hydrofluoric component of the acidizing solution is spent. The previously dissolved silicon precipitates in the form of an amorphous gel which blocks the flow paths in the sandstone and may reduce permeability. The rate and severity of silicon precipitation depends on formation characteristics. For example, the rate of silicon precipitation increases as reservoir clay content and reservoir temperature increase. Also, the severity of damage increases as reservoir permeability decreases.
During an acidizing process the acidizing solution attacks the siliceous components of the reservoir. Clay minerals are particularly susceptible to attack due to their high surface area and open structure. Clays have a layered structure composed of two basic structural units, a silica sheet and an alumina sheet. The manner in which these sheets are stacked plus the degree of substitution of other elements determines the type of clay. Clays react with hydrofluoric acid to form silicon and aluminum fluorides. For example, the reaction with kaolinite clay is: Al.sub.2 Si.sub.2 O.sub.5 (OH).sub.4 +18 HF.fwdarw.2H.sub.2 SiF.sub.6 +2AlF.sub.3 +9H.sub.2 O. Kaolinite clay is a common reservoir mineral often responsible for formation damage. However, a distribution of reaction products will be present in a spent acidizing solution from a reservoir containing a variety of clays. Silicon fluorides exist as SiF.sub.4, SiF.sub.5.sup.-, and SiF.sub.6.sup.-2 while the aluminum and aluminum fluorides exist as Al.sup.+3, AlF.sup.+2, AlF.sub.2.sup.+, AlF.sub.3, AlF.sub.4.sup.-, AlF.sub.5.sup.-2 and AlF.sub.6.sup.-3.
The presence of active aluminum and aluminum fluorides in the spent or partially spent acidizing solution aggravates silicon precipitation. A spent hydrofluoric and hydrochloric acid mixture is spent in the hydrofluoric component, but still has live hydrochloric acid which continues to leach aluminum from the unreacted clay minerals and other minerals remaining in the sandstone. The leached aluminum competes with silicon for the fluoride provided by hydrofluoric acid. Since aluminum is a stronger complexer of fluoride ions than silicon, the soluble silicon fluorides are converted to insoluble silicon gels as the fluoride ions complex with the soluble aluminum. Consequently, the precipitated insoluble silicon gel deposits in the formation pores and may reduce permeability.
Various approaches to the problem of silicon precipitation have been suggested.
In Shaughnessy and Kunze, infra at page 1201, three techniques are suggested for minimizing silicon precipitation. The first suggested technique is use of an afterflush following acidizing. According to Shaughnessy and Kunze, afterflushing with diesel oil, nitrogen, HCl or ammonium chloride in water following an acidizing treatment displaces spent acidizing solution from the critical region very close to the well. Any damage to the reservoir caused by silicon precipitation is far enough from the wellbore to have a reduced effect on flow capacity. However, an afterflush has some disadvantages. It is an added expense and may aggravate a temporary water block. It must be pumped soon after acidizing to be most effective. Also, some damage from silicon precipitation still occurs. The second technique for reducing silicon precipitation suggested by Shaughnessy and Kunze is to return the well to production immediately after acidizing. However, such a technique is inapplicable to situations where immediate production is either undesirable or impossible due to operational constraints or reservoir limitations. The third technique suggested by Shaughnessy and Kunze is particularly for high-temperature wells (above 95.degree. C. or 200.degree. F.). In such wells, reduced hydrofluoric acid concentration is recommended to reduce silicon precipitation. However, acidizing with lower hydrofluoric acid concentration only delays silicon precipitation while reducing the dissolving power of the acid.
In U.S. Pat. No. 2,225,695 (Henderson et al) a method for acid treating a subterranean formation is disclosed. The formation is first acidized with a 24 to 60 weight percent hydrofluoric acid solution. A gelatinous aggregate of reaction products is allowed to precipitate. Then an agent, such as hydrochloric acid, is injected into the formation to dissolve the precipitate. This two step process results in extra time and expense in treating the formation. Furthermore, blockage caused by precipitation limits contacting all of the precipitated material for removal.
In addition to aggravating formation damage due to silicon and aluminum precipitation, conventional acidizing solutions also have a tendency to corrode tubing, casing and downhole equipment, such as gravel pack screens and downhole pumps. This is particularly true of conventional acidizing solutions of hydrofluoric and hydrochloric acids which are typically low pH, high acidity solutions. Further, the iron which is removed by equipment corrosion during an acidizing process may precipitate in the formation and cause additional damage.
The acidizing process in a gas well makes downhole equipment particularly sensitive to low pH acidizing solutions in that some spent acidizing solution may be left in the wellbore after the well is put back on production. The spent acidizing solution may contain live HCl which is circulated by and through the tubing and downhole equipment during production, increasing the opportunity for corrosion of equipment.
Some corrosion problems may be alleviated by the use of a corrosion inhibitor with the conventional acidizing solution. However, corrosion inhibitors provide only short-term protection. Further, corrosion inhibitors reduce oil production by adsorbing on the rock matrix, changing the rock from water-wet to oil-wet and thereby reducing relative permeability (C. W. Crowe, S. S. Menor, SPE 10650, p. 59 (1982)). Corrosion inhibitors are also difficult to use in that they are only dispersible in the acidizing solution and have a tendency to undergo phase separation.
Corrosion problems are aggravated in high temperature (greater than about 250.degree. F.) wells where heat increases the rate of corrosion. Also, corrosion inhibitors are not as effective at high temperatures as they are at low temperatures.
Therefore, the need exists for an acidizing solution which will increase formation permeability without creating precipitation and corrosion problems.